Alerts

PHMSA Issues Final Rule Allowing Integrity Management Alternative for Class Location Changes

January 15, 2026

On January 14, 2026, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published a final rule amending its gas pipeline safety regulations to allow operators of gas transmission pipelines to implement an Integrity Management (IM) alternative to manage class location changes. The IM alternative allows operators to confirm or restore the maximum allowable operating pressure (MAOP) of certain eligible pipeline segments without replacing pipe or reducing operating pressure. It is modeled on PHMSA’s longstanding policy of granting special permits or waivers to operators that comply with a series of additional terms and conditions consistent with IM principles.

The final rule becomes effective March 16, 2026. In addition, PHMSA requests comments on new information collection requests for a new Class Location Notification Requirement under existing § 192.18, and a new Class Location Records Requirement. Comments are due on the information requests by March 16, 2026.

Background

Section 192.611 of PHMSA’s regulations provides that, if the class location of a gas transmission pipeline segment changes, and the hoop stress corresponding to the pipeline’s established MAOP is not commensurate with the present class location, the operator must confirm or revise the MAOP of the line segment. If the hoop stress corresponding to the MAOP exceeds specified limitations, the operator must either pressure test the line to confirm MAOP, reduce MAOP, or replace the segment. Pipelines seeking to waive the requirements of § 192.611 have been required to obtain a special permit and comply with additional safety requirements.

The Final Rule

Eligibility to Use IM Alternative

Under new § 192.611(a)(4), an operator may confirm or restore the MAOP of an “eligible Class 3 segment” by complying with existing Subpart O integrity management requirements and with additional more stringent requirements. The final rule also introduced two new definitions in § 192.3: “eligible Class 3 segment”; and “eligible Class 3 inspection area”.

An “eligible Class 3 segment” is defined as “a segment of a transmission pipeline in a Class 3 location that is capable of being assessed with an instrumented inline inspection [ILI] tool and does not contain: bare pipe; wrinkle bends; pipe with a seam formed by lap welding; a seam with a longitudinal joint factor below 1.0; or a segment that has experienced an in-service leak or rupture due to cracking in the pipe body, seam, or girth weld on the segment or segments of similar characteristics in or within 5 miles.”

In an important departure from the notice of proposed rulemaking, pipeline segments with seams manufactured by direct current (DC) electric resistance welding (ERW), low-frequency (LF) ERW, and electric flash welding (EFW) are not excluded as eligible Class 3 segments and may qualify for the IM alternative.

An “eligible Class 3 inspection area” is defined as “an eligible Class 3 segment and the upstream and downstream portion of the transmission line that is capable of being assessed with an [ILI] tool extending from the nearest [ILI] tool launcher to the nearest [ILI] tool receiver.”

The IM alternative is available only to eligible Class 3 segments that were originally located in areas designated as Class 1 or Class 2 based on population density. An operator may apply the IM alternative to pipeline segments that were previously denied a special permit or on which MAOP was previously reduced.

An operator may not apply the IM alternative to gas gathering pipelines or distribution pipelines or to a pipeline segment with an MAOP that exceeds 72 percent of specified minimum yield strength (SMYS).

The IM Alternative

The IM alternative contains initial and recurring programmatic requirements that must be completed by no later than March 16, 2028, or within 24 months of the date of the class location change, whichever is later.

Initial Programmatic Requirements

Baseline Integrity Assessment and Remediation. An operator must conduct a baseline assessment of the eligible Class 3 inspection area and remediate anomalies in accordance with Subpart O requirements in § 192.933. The primary assessment method is an ILI tool. Validation of ILI assessment results must be performed to at least Level 2 in accordance with API STD 1163. An operator may not perform integrity assessments using direct assessment methods. Operators may rely on a prior assessment if it was conducted after March 16, 2024, or within 24 months of the class location change, whichever is later.
Pressure Testing. Operators must test the eligible Class 3 segment to a pressure at least 1.25 times the MAOP in accordance with Subpart J. Results from a prior pressure test, including a pre-1970 pressure test, may be used to satisfy the pressure testing requirement if the test was conducted for a duration consistent with Subpart J.
Material Records Verification. An operator must confirm that the eligible Class 3 segment has traceable, verifiable, and complete (TVC) records available for pipe diameter, wall thickness, grade, seam type, yield strength, and tensile strength. This confirmation must occur within the 24-month compliance period, which accelerates the compliance timeline for material records confirmation that applies under § 192.607.
Rupture Mitigation Values. Rupture mitigation valves must be located on both sides of the eligible Class 3 segment. An operator may upgrade existing valves that do not have rupture mitigation technology and retain the valve spacing requirements based on the pipeline’s original class location.
Cathodic Protection. At least one cathodic protection pipe-to-soil test station is required on the eligible Class 3 segment in accordance with § 192.469, with a maximum spacing between test stations of 1/2 mile. Where obstructions or restricted areas prevent placement of test stations in an appropriate location, test stations may be placed in the closest practical location.
Depth of Cover. Operators must perform a depth of cover survey of the eligible Class 3 segment and remediate any locations that do not conform to the requirements in § 192.327 for the original class design.
Coating Survey. Operators must perform a coating survey of the eligible Class 3 segment and remediate specified conditions in accordance with § 192.461(f) through (h).
Notification Requirement. An operator using the IM alternative to confirm MAOP of an eligible Class 3 segment must notify PHMSA (and any State or local pipeline safety authority, if applicable) in accordance with § 192.18(a) and (b). PHMSA approval to use the IM alternative is not required in advance.

Recurring Programmatic Requirements

The IM alternative also requires compliance with additional operation and maintenance measures intended to protect the pipeline from the threat of corrosion and excavation damage. These measures exceed the requirements of Subpart O.

Gas Quality. Operators must ensure that, except during abnormal operations, the quality of the gas transported in an eligible Class 3 segment is consistent with provisions contained in a pipeline’s tariff and does not contain (1) more than 3 percent carbon dioxide by volume, (2) more than seven pounds of water per million cubic feet of gas or any free water, and (3) more than one grain of hydrogen sulfide per 100 cubic feet of gas.
Close Interval Surveys. Operators must perform close interval surveys of the eligible Class 3 segment at least once every 7 calendar years, not to exceed 90 months.
Patrolling. Operators must perform right-of-way patrols of the eligible Class 3 segment in accordance with § 192.705(a) and (c) at least once per month, not to exceed 45 days.
Leak Surveys. Operators must perform leakage surveys of the eligible Class 3 segment in accordance with § 192.706 at least four times per calendar year, not to exceed 4 ½ months.
Line Markers. Line markers must be visible from at least one other line marker, and missing line markers must be replaced within 30 days of discovery.
Shorted Casings. If an operator identifies any metallic or electrolytic shorts in the eligible Class 3 segment, the shorted casing must be cleared within 1 year of identification. If clearing the short is impracticable, operators must take other measures to minimize corrosion inside the casing.
Class Location Studies. Operators must conduct a class location study of the eligible Class 3 inspection area in accordance with § 192.609 at least once each calendar year, not to exceed 15 months.
Exposed Pipe and Weld Surface Examinations. Whenever the eligible Class 3 segment is exposed and the coating is removed, an operator must examine the pipe and weld surfaces for cracking using non-destructive examination methods and procedures appropriate for the pipe and integrity threat conditions. An operator must also analyze the predicted failure pressure and critical strain level of any cracking in accordance with § 192.712 and remediate in accordance § 192.933.

Information Collection Requests

Under the Paperwork Reduction Act, PHMSA is required to provide an opportunity for the public to comment on the new notification and recordkeeping requirements contained in the final rule. PHMSA will submit information collection requests to the Office of Management and Budget requesting approval for them. The final rule requires that interested parties submit comments on these information collections to PHMSA by March 16, 2026.

For More Information

Van Ness Feldman counsels clients on pipeline safety compliance, enforcement, litigation under state and federal Pipeline Safety Laws and regulations, and with safety requirements applicable to the transportation of hazardous materials. If you would like additional information about PHMSA’s Class Location Final Rule or assistance submitting comments on the proposed information collections, please contact Joseph Hainline, Susan Olenchuk, or any member of the firm’s Pipeline & LNG practice group.